Process for treating an oil well

ABSTRACT

A method of treating a subterranean formation, the method comprising: (A) injecting down a well bore into the formation an admixture of (a) an emulsion having an internal aqueous phase comprising a water-soluble oil or gas field chemical or an aqueous dispersion of a water-dispersible oil or gas field chemical and an external oil phase comprising a liquid hydrocarbon and an oil-soluble surfactant and (b) a demulsifier comprising a solution of a surfactant having a cloud point temperature of above 40 ° C.; or (B) separately injecting down a well bore into the formation emulsion (a) and demulsifier (b) and generating an admixture of emulsion (a) and demulsifier (b) within the formation.

[0001] The present invention relates to a method for inhibitingdeleterious processes in a well such as an oil well, particularly, butnot exclusively, for inhibiting scale deposition.

[0002] U.S. Pat. No. 4,517,102 teaches that generally, emulsions may bebroken by adding demulsifiers to the pre-existing emulsions. Thedemulsifiers act with the surfactants (which induce emulsification andencapsulation) to cause an inversion and separation of the emulsionphase. It is stated that, unfortunately, adding demulsifiers to injectedemulsions is impossible. When the fluids are not being pumped, mixing islimited to the interface. Pumping would require further displacement ofthe emulsion within the formation. Thus, stepwise injection of anemulsion and a demulsifier is not deemed feasible. U.S. Pat. No.4,517,102 is silent concerning simultaneous injection of an admixture ofan emulsion and a demulsifier. However, the skilled person would beconcerned that addition of a demulsifier to an emulsion may cause aninversion and separation of the emulsion phase before the emulsion canbe injected down the wellbore. Also, the skilled person would anticipatethat on-the-fly mixing of the emulsion and demulsifier may causepremature inversion of the emulsion phase in the well bore before theemulsion phase can enter the formation. According to U.S. Pat. No.4,517,102, in well treatment operations, several alternative schemes areused. In one system the emulsion surfactant is selected so that it willprefer to wet the surface of the formation rock. In this way, as theemulsion passes into the formation, the surfactant is removed from theemulsion in a sufficient amount to cause separation. In a second system,a mixture of surfactants is selected so that the emulsion will becomeunstable above a certain temperature. As the fluid temperature risestoward the formation temperature, the emulsion breaks. In a thirdsystem, the emulsion may be broken mechanically. The emulsion dropletsbreak when they are squeezed into pores within the formation.

[0003] It has now been found that contrary to the teachings of U.S. Pat.No. 4,517,102 that stepwise injection of an emulsion and a demulsifieris feasible. It has further been found that it is possible to inject anadmixture of a water-in-oil emulsion and a demulsifier into a formationwithout the emulsion breaking prematurely either prior to being injectedinto the wellbore or within the well bore.

[0004] Thus, according to the present invention there is provided amethod of treating a subterranean formation, the method comprising:

[0005] (A) injecting down a well bore into the formation an admixture of(a) an emulsion having an internal aqueous phase comprising an aqueoussolution of a water-soluble oil or gas field chemical or an aqueousdispersion of a water-dispersible oil or gas field chemical and anexternal oil phase comprising a liquid hydrocarbon and an oil-solublesurfactant and (b) a demulsifier comprising a solution of a surfactanthaving a cloud point temperature of above 40° C.; or

[0006] (B) separately injecting down a well bore into the formationemulsion (a) and demulsifier (b) and generating an admixture of emulsion(a) and demulsifier (b) within the formation.

[0007] The demulsifier acts by breaking down the emulsion within theformation (by inversion) to release the oil or gas field chemical intocontact with the surfaces of the pores of the formation. For example,where the aqueous phase of the emulsion contains a scale inhibitor, theinhibitor will adsorb or precipitate onto the surfaces of the pores ofthe formation, while the oil phase will remain in continuity with anyhydrocarbon, for example, oil present in adjacent pores so thatsubsequent flow of hydrocarbon through the formation is not suppressed.

[0008] An advantage of the process of the present invention is that theemulsion breaks more cleanly in the presence of the demulsifier thanwhen relying on the inherent properties of the emulsion and thetemperature, time, or mechanical stresses to which it is subjected toseparate the phases.

[0009] The emulsion employed in the present invention may be made in abasic three step approach. The first step is to form either (i) anaqueous solution of a suitable water-soluble oil or gas field chemicalor (ii) an aqueous dispersion of a suitable water-dispersible oil or gasfield chemical.

[0010] The water which is used to form the aqueous solution ordispersion may be pure water, tap water, deionised water, seawater,sulphate reduced seawater or a synthetic brine. It will be appreciatedthat the aqueous solution or dispersion may also include liquids otherthan water, for example alcohols, as long as they are not soluble in theoil phase.

[0011] Suitable water-soluble or water-dispersible oil or gas fieldchemicals may be (i) scale inhibitors, (ii) corrosion inhibitors, (iii)inhibitors of asphaltene deposition, (iv) hydrogen sulphide scavengersor (v) hydrate inhibitors.

[0012] Scale inhibitors include water-soluble organic molecules havingat least 2 carboxylic and/or phosphonic acid and/or sulphonic acidgroups e.g. 2-30 such groups. Preferred scale inhibitors are oligomersor polymers, or may be monomers with at least one hydroxyl group and/oramino nitrogen atom, especially in hydroxycarboxylic acids or hydroxy oraminophosphonic, or, sulphonic acids. Scale inhibitors are usedprimarily for inhibiting calcium and/or barium scale. Examples of suchcompounds used as scale inhibitors are aliphatic phosphonic acids having2-50 carbons, such as hydroxyethyl diphosphonic acid, and aminoalkylphosphonic acids, e.g. polyaminomethylene phosphonates with 2-10 N atomse.g. each bearing at least one methylene phosphonic acid group; examplesof the latter are ethylenediamine tetra(methylene phosphonate),diethylenetriamine penta(methylene phosphonate) and the triamine- andtetramine-polymethylene phosphonates with 2-4 methylene groups betweeneach N atom, at least 2 of the numbers of methylene groups in eachphosphonate being different (e.g. as described further in publishedEP-A-479462, the disclosure of which is herein incorporated byreference). Other scale inhibitors are polycarboxylic acids such asacrylic, maleic, lactic or tartaric acids, and polymeric anioniccompounds such as polyvinyl sulphonic acid and poly(meth)acrylic acids,optionally with at least some phosphonyl or phosphinyl groups as inphosphinyl polyacrylates. The scale inhibitors are suitably at leastpartly in the form of their alkali metal salts e.g. sodium salts.

[0013] Examples of corrosion inhibitors are compounds for inhibitingcorrosion on steel, especially under anaerobic conditions, and mayespecially be film formers capable of being deposited as a film on ametal surface e.g. a steel surface such as a pipeline wall. Suchcompounds may be non-quaternised long aliphatic chain hydrocarbylN-heterocyclic compounds, where the aliphatic hydrocarbyl group may beas defined for the hydrophobic group above; mono- or di-ethylenicallyunsaturated aliphatic groups e.g. of 8-24 carbons such as oleyl arepreferred. The N-heterocyclic group can have 1-3 ring nitrogen atomswith 5-7 ring atoms in each ring; imidazole and imidazoline rings arepreferred. The ring may also have an aminoalkyl e.g. 2-aminoethyl orhydroxyalkyl e.g. 2-hydroxyethyl substituent. Oleyl imidazoline may beused. Where corrosion inhibitors are released into the formation usingthe method of the present invention, these inhibitors are effective inreducing corrosion of metal surfaces as they are produced out of thewell.

[0014] Asphaltene inhibitors include amphoteric fatty acid or a salt ofan alkyl succinate while the wax inhibitor may be a polymer such as anolefin polymer e.g. polyethylene or a copolymeric ester, e.g.ethylene-vinyl acetate copolymer, and the wax dispersant may be apolyamide.

[0015] Hydrogen sulphide scavengers include oxidants, such as inorganicperoxides, e.g. sodium peroxide, or chlorine dioxide, or aldehydes e.g.of 1-10 carbons such as formaldehyde or glutaraidehyde or(meth)acrolein.

[0016] Hydrate inhibitors include salts of the formula [R¹(R²)XR³]⁺Y⁻,wherein each of R¹, R² and R³ is bonded directly to X, each of R¹ andR², which may the same or different is an alkyl group of at least 4carbons, X is S, NR⁴ or PR⁴, wherein each of R³ and R⁴, which may be thesame or different, represents hydrogen or an organic group with theproviso that at least one of R³ and R⁴ is an organic group of at least 4carbons and Y is an anion. These salts may be used in combination with acorrosion inhibitor and optionally a water soluble polymer of a polarethylenically unsaturated compound. Preferably, the polymer is ahomopolymer or a copolymer of an ethylenically unsaturatedN-heterocyclic carbonyl compound, for example, a homopolymer orcopolymer of N-vinyl-omega caprolactam. Such hydrate inhibitors aredisclosed in EP 0770169 and WO 96/29501 which are herein incorporated byreference.

[0017] Preferably, the oil or gas field chemical may be dissolved ordispersed in the internal aqueous phase of the emulsion in an amount inthe range of from 1 to 50 percent by weight, preferably 5 to 30 percentby weight.

[0018] The second step is to blend a suitable liquid hydrocarbon with asuitable oil-soluable surfactant. The liquid hydrocarbon selected may bea crude oil or a refined petroleum fraction such as diesel oil, gascondensate, gas oil, kerosene, gasoline and the like, or may be abiodiesel. Particular hydrocarbons such as benzene, toluene,ethyl-benzene, cyclohexane, hexane, decane, hexadecane, long chainsalcohols (e.g. C10), and the like may also be used. Preferably, theliquid hydrocarbon is kerosene or a base oil (a refined hydrocarbon)

[0019] The oil-soluble surfactant must have a hydrophilic/lipophilicbalance (HLB) suited to the other liquids present in the emulsion.Preferably, the oil-soluble surfactant has an HLB value of less than 8,preferably less than 6, more preferably in the range 4 to 6. Examples ofsuitable surfactants include sorbitan monooleate, sorbitan monostearate,sorbitan trioleate, sorbitan monopalmitate, sorbitan tristearate,non-ionic block co-polymers, polyoxyethylene stearyl alcohols,polyoxyethylene cocoa amines, fatty amine ethoxylates, polyoxyethyleneoleyl alcohols, polyoxyethylene stearyl alcohols, polyoxyethylene cetylalcohols, fatty acid polyglycol esters, glyceryl stearate, glyceryloleate, propylene glycol stearate, polyoxyethylene oleates,polyoxyethylene stearates, and diethylene glycol stearate. More than oneoil-soluble surfactant may be employed.

[0020] Typically, minor amounts of oil-soluble surfactant are blendedwith the liquid hydrocarbon. The concentration of oil-soluble surfactantin the blend of oil-soluble surfactant and liquid hydrocarbon may be inthe range of from 0.1 to 6 percent by weight, preferably 0.2 to 2percent by weight.

[0021] It will be appreciated that the order of the first and secondsteps may be reversed or the first and second steps may be performedsimultaneously.

[0022] The third step is to form the emulsion, which is preferablyaccomplished by slowly pouring the aqueous solution or dispersion intothe blend of the liquid hydrocarbon/oil-soluble surfactant whileintensive blending is applied. The blending operation for the emulsionshould be designed to minimise the size of the internal phase waterdroplets since this may increase the stability of the emulsion. Smallaqueous droplets can be prepared by thoroughly emulsifying the aqueousand hydrocarbon phases. Preferably, emulsification is accomplished byslowly pouring the aqueous solution or dispersion into the blend ofliquid hydrocarbon/oil-soluble surfactant while intensive blending isapplied. The mixture should be vigorously stirred or sheared for about 5to 20 minutes, the rate of shear being highly dependent on the size andtype of mixing device employed. In oil or gas field operations,mechanical mixing equipment or blenders may be used to impart thedesired shear to the mixture. Stirring rate and times should be designedto form small aqueous droplets having average diameters of from about0.01 to about 100 microns and preferably from about 0.1 to about 10microns.

[0023] Preferably, the internal aqueous phase of the emulsion shouldamount to from 10 to 70 percent, more preferably from 30 to 60 percentof the total volume of the emulsion.

[0024] Density control of the emulsion may be used to enhance thestability of the emulsion (measured in the absence of the demulsifier).This may be accomplished by addition of weighting agents to the internalaqueous phase of the emulsion. For example, minor amounts of solublesalts such as sodium or potassium chloride may be added to the internalaqueous phase. Suitably, the aqueous phase may comprise from 0.5 to 20percent by weight of soluble salts. Preferably, the emulsion is stable,in the absence of the demulsifier, at the most extreme conditions oftemperature and pressure existing in the well bore and/or the formation.

[0025] Suitably, the demulsifier comprises a solution of a surfactanthaving a cloud point temperature of at least 40° C., preferably at least50° C., more preferably at least 60° C. The cloud point temperature of asurfactant is defined as the temperature at which an aqueous solution ofthe surfactant becomes cloudy as the surfactant comes out of thesolution. Without wishing to be bound by any theory, it is believedthat, as the surfactant of the demulsifier comes out of solution, thesurfactant will travel to the interface of the emulsion therebyassisting in the breakdown of the emulsion. The cloud point temperaturetherefore provides an indication of the temperature at which thedemulsifier will be expected to break the emulsion. The cloud pointtemperature is dependent upon both the nature of the surfactant and itsconcentration. It will be appreciated that the temperature in the regionof the formation into which the admixture of the demulsifier and theemulsion is to be injected or in which the admixture is to be generatedwill be different for different wells, and so breakdown of the emulsionhas to be suited to that well. For example, in one well it may bedesirable for the emulsion to break down at a temperature of 115° C.,while in another well the break-down temperature might be 130° C. or 75°C. The demulsifier should therefore comprise a surfactant selected tosuit the particular well at a concentration which allows breakage of theemulsion at the optimum temperature for that well. Preferably, thedemulsifier comprises a surfactant at a concentration such that thedemulsifier has a cloud point temperature of at least 15° C. less,preferably at least 30° C. less, more preferably at least 50° C. lessthan the formation temperature. Preferably, the demulsifier comprisesmore than one surfactant.

[0026] Suitably the demulsifier comprises at least one surfactantselected from the group consisting of:

[0027] (a) polyamine salts such as polyester amines, amino methylatedpoly acrylamide, poly di-methyl amino propyl methacrylamide, polydimethyl amino ethyl acrylate, poly ethylene imine, poly vinylpyrrolidone, caprolactam-based polymers and quaternised versions of theabove. Suitably, the molecular weight of the polyamine salt is above3000;

[0028] (b) multifunctional polyethers such as sulfated triglycerides;

[0029] (c) polyethers, such as copolymers of ethylene oxide andpropylene oxide and the reaction products of such copolymers withdiacids, diepoxides, diisocyanates, aldehydes, and diamines. Suitably,the molecular weight of the polyether is above 2000; and

[0030] (d) p-alkylphenol-formaldehyde resins and ethylene oxide and/orpropylene oxide derivatives thereof.

[0031] Suitably, the demulsifier comprises a solution of thesurfactant(s) dissolved in an aqueous or organic solvent such asmonoethylene glycol (MEG), tetraethylene glycol (TEG), butylethyleneglycol (BGE), butyldiethylene glycol (BDGE), water, xylene and toluene.Typically, the demulsifier contains minor amounts of surfactant(s) sincethe use of excessive quantities of surfactant(s) may prematurely resultin destruction of the emulsion by inversion. Preferably, theconcentration of surfactant(s) in the demulsifier is generally in therange of from 0.01 to 5 percent by weight, preferably 0.1 to 2 percentby weight, for example, 0.2 to 1 percent by weight. As discussed above,the cloud point of a surfactant is concentration dependent. Thus, thetemperature at which the emulsion breaks can be precisely controlled byadjusting the concentration of surfactant(s) in the demulsifier.

[0032] The admixture of emulsion and demulsifier may be generated withinthe formation by injecting the emulsion into the well bore prior to theinjection of the demulsifier. This ensures that the emulsion will beuncontaminated by any of the demulsifier during injection down the wellbore. However, it is envisaged that by appropriate selection of thesurfactant(s) of the demulsifier and of the concentration of thesurfactant(s), the demulsifier may be injected down the well bore priorto injection of the emulsion without premature breaking of the emulsionin the well bore.

[0033] If desired, a spacer may be employed between the emulsion anddemulsifier to ensure that mixing does not take place before theemulsion and demulsifier enter the formation. Suitably, the spacer maybe aqueous (for example, pure water, tap water, deionised water,seawater, sulphate reduced seawater, production water or a syntheticbrine, such as a KCl brine) or a liquid hydrocarbon (for example, aglycol ether such as butyl glycol ether, butyl diglycol ether andethylene glycol monobutyl ether, or crude oil, or a refined petroleumfraction such as kerosene, diesel and base oil or a biodiesel).

[0034] Where the emulsion is injected into the well bore prior toinjection of the demulsifier, the emulsion will enter the formationbefore the demulsifier. Without wishing to be bound by any theory, thedemulsifier is less viscous than the emulsion and will have a highervelocity than the emulsion within the formation. Accordingly, thedemulsifier will overtake the emulsion in the formation leading to insitu generation of an admixture of the emulsion and demulsifier.

[0035] Where the demulsifier is injected into the well bore prior toinjection of the emulsion, the demulsifier will enter the formationbefore the emulsion. Without wishing to be bound by any theory, thedifference in the velocities of the emulsion and demulsifier within theformation will result in the demulsifier being back produced over theemulsion (when the well is put back into production) thereby generatingan admixture of the emulsion and demulsifier.

[0036] It is preferred to inject an admixture of the emulsion anddemulsifier down the well bore. Thus, in a preferred embodiment of thepresent invention there is provided a method of treating a subterraneanformation, the method comprising the steps of:

[0037] A) preparing an admixture of (a) an emulsion having an internalaqueous phase comprising an aqueous solution of a water-soluble oil orgas field chemical or an aqueous dispersion of a water-dispersible oilor gas field chemical and an external oil

[0038] B) phase comprising a liquid hydrocarbon and an oil-solublesurfactant and (b) a demulsifier comprising a solution of a surfactanthaving a cloud point temperature of above 40° C.; and

[0039] C) injecting the admixture down a well bore into the formation.

[0040] Preferably, the admixture is injected down the well bore at arate such that the residence time of the admixture of emulsion anddemulsifier in the well bore is less than the breakage time of theemulsion under the conditions within the wellbore.

[0041] By “breakage time” is meant the time taken for demulsifier tocause inversion of the emulsion at the most extreme conditions oftemperature and pressure within the wellbore, for example, theconditions at the bottom of the wellbore.

[0042] Where an admixture of the emulsion and demulsifier is to beinjected into the well bore, the temperature in the well bore andformation should be modeled so that a demulsifier may be selected havingat least one surfactant chosen to suit the conditions in the well boreand formation at a concentration chosen so as to avoid prematurebreakage of the emulsion in the well bore and to allow breakage of theemulsion in the formation at a targeted radial distance from the wellbore. In particular, the demulsifier should comprise a surfactant havinga cloud point temperature, at the chosen concentration of surfactant,which is substantially above ambient temperature so as to mitigate therisk of the emulsion breaking as the demulsifier is admixed with theemulsion.

[0043] It is envisaged that the admixture of the emulsion anddemulsifier may be prepared by on-the-fly mixing of the emulsion anddemulsifier. Alternatively, the admixture may be prepared using surfacemixing equipment. The time interval between preparation of theadmixture, using the surface mixing equipment, and injection of theadmixture down the wellbore is typically less than 12 hours, preferablyless than 5 hours, more preferably less than 1 hour and most preferablyless than 0.5 hours. Generally, the admixture will be injected down thewellbore immediately after its preparation using the surface mixingequipment

[0044] The invention will now be illustrated by the following examplesand by reference to FIGS. 1 to 4.

[0045] Emulsions

[0046] The formulations of Emulsions A to C together with details oftheir preparation are provided in Table 1.

[0047] Aqueous Solution of Scale Inhibitor

[0048] The aqueous solution of scale inhibitor used in the Comparativetest comprised 10 wt % DETAPMH [diethylenetriamine(pentamethylene)phosphonic acid].

[0049] Droplet Size Distributions.

[0050] Droplet size distributions of Emulsions A to C were determinedusing a Galai Computerised Inspection System, CIS-1. Prior to analysis,the emulsions were diluted either in cyclohexane or kerosene (1-2 dropsof emulsion in approximately 5 ml diluent). The median diameters of thedroplets of the aqueous phase are given in Table 2 below.

[0051] Stability-Temperature Determinations.

[0052] The stability of Emulsions A to C was assessed mainly by visualobservation. Some limited periodic determinations of droplet size werealso carried out. The formulations were designed to be stable towardscoalescence and bulk phase separation under ambient conditions, althoughsome creaming and sedimentation with time is inevitable. In addition tothe ambient temperature observations, aliquots (10-20 ml) of theemulsions were also incubated in tightly-stoppered vials at 80, 100 and(when necessary) 120° C. for visual observation of stability. In thisway, phase separation and the formation of any middle phases wereevaluated qualitatively as a function of time. Stability-temperaturedata for the emulsions are given in Table 2 below.

[0053] Rheological Determinations.

[0054] The rheology of Emulsions A to C was examined in order todetermine whether the emulsions could be pumped downhole under “worstcase” conditions at the oil or gas field production site. The C25measuring system of a Bohlin VOR rheometer was used to measure apparentviscosity as a function of shear rate at 5° C., chosen as a typicalambient temperature. The data is provided in Table 2 below. The measuredapparent viscosities would allow the emulsions to be deployed downholeunder typical field conditions.

[0055] Coreflood Experiments

[0056] Core flooding experiments were used to compare the performance ofadmixtures of Emulsion C and demulsifier (Floods 2 and 3) with thesolution of scale inhibitor in seawater (Flood 1). The performance ofthe scale inhibitor formulations was evaluated by comparing thegenerated inhibitor desorption profiles and also by any permeability orsaturation changes apparent after the injection of the formulations.Berea outcrop rock was used for the core material. The liquid phasescomprised a refined oil (Isopar H) and a standard brine (syntheticseawater prepared in the laboratory; filtered using 0.45 micron membranebefore use). The test sequence was as follows:

[0057] A core plug was saturated with the brine, and the pore volume wasdetermined. The core plug was then equilibrated to the test temperature(100° C.). The absolute permeability of the core plug to the brine(K_(abs)), the relative permeabilities of the core plug to brine and oiltogether with the end state saturation levels of the core plug weremeasured. With the core plug at residual brine saturation, the core plugwas cooled to the injection temperature (60° C.). 8 pore volumes ofscale inhibitor formulation (admixtures of Emulsion C with 4.7g of BakerPetrolite ML 3407 demulsifier per 100 g of emulsion; or the aqueoussolution of scale inhibitor) was then injected. In each case, theinjected scale inhibitor formulation contained 10 wt % scale inhibitorin the aqueous phase.

[0058] The core plug was shut in and the temperature raised to 100° C.The core plug was then backflushed with oil, and, the permeability ofthe core plug to oil was measured (once steady-state conditions wereattained). The residual brine saturation was then calculated and theinhibitor content of the eluted brine analysed. The core plug was thenbackflushed with brine (seawater), and an inhibitor desorption profilewas determined. The permeability of the core plug to brine was alsodetermined. The core plug was then flushed with oil to attain theresidual brine saturation, and the permeability of the core plug to oilwas re-measured. Permeabilities were calculated from a linear regressionof at least 4 pressure drop/fluid flow rate data pairs.

[0059] The results of these tests are summarized in Table 2. The resultsshow that there was little difference between the tests which employedthe admixtures of Emulsion C and demulsifier and the test which employedthe aqueous solution of scale inhibitor in terms of fluid saturations orreturn permeabilities. Both systems tended to increase the core plugresidual oil saturation (by slightly more in the case of the admixturesof Emulsions C and demulsifier), resulting in a reduced brinepermeability at S_(or) (residual oil saturation) in all cases. Thereduction in S_(wi) (initial water saturation) caused by the inhibitorformulations resulted in a slightly increased oil permeability in thecase of the aqueous solution of scale inhibitor (Flood 1), whereas asmall decrease in oil permeability was observed after the treatment withthe admixtures of Emulsion C and demulsifier (Floods 2 and 3). This maybe due to some unbroken emulsion remaining in the core; emulsion waseluted during the oil back flush and the pressure drop profile exhibitedspikes (see FIG. 3) which may have coincided with the displacement ofthe higher viscosity emulsion from the core plug.

[0060]FIG. 1 compares the injection pressures observed in Floods 1 and2, from which it can be seen that the injection pressure of theadmixture of emulsion C and demulsifier is much greater than would beexpected from the viscosity difference between Emulsion C and theaqueous solution of scale inhibitor (12cP compared with 0.82cP).Examination of Emulsion C under a microscope (prior to injection)indicated a droplet size of approximately 5 μm, which falls into theregion where bridging of the Berea rock pore throats may be expected. Abuild up of droplets at the inlet end of the core may explain the highpressure observed. However, the inhibitor is known to have entered thecore plug from the measured fluid saturations, and also because a gooddesorption profile was obtained. Therefore, without wishing to be boundby any theory, either the droplets deform to permit entry into thepores, or they break under the pressure build up and the system is nolonger fully emulsified as it penetrates the rock. Emulsion C used inFlood 3 underwent additional mixing which gave an approximate dropletsize of 1-2 μm. The resultant injection pressure is shown in FIG. 2together with that of the aqueous solution of the scale inhibitor forcomparison (Flood 1), and it can be seen that a much lower pressure dropwas generated by the admixture of Emulsion C and demulsifier of Flood 3than in Flood 2. Reference to the viscosity and relative permeabilitydifferences between the admixtures of Emulsion C and the aqueous scaleinhibitor solution can account for the observed pressure difference. Allthe data therefore indicate that formulations comprising admixtures ofEmulsion C and demulsifier remain emulsified during injection.

[0061] The pressure required to instigate flow after the inhibitorshut-in is indicative of the drawdown needed to bring a well back ontoproduction after a squeeze treatment. FIG. 3 shows the pressure recordedduring the oil back flush in Floods 1 and 2, from which it can be seenthat a lower pressure was observed after the treatment with theadmixture of Emulsion C and demulsifier.

[0062] The inhibitor desorption profiles are shown in FIG. 4 for thesandstone tests. The data indicate that for the core floods whichemployed the admixture of Emulsion C and demulsifier (Floods 2 and 3)the scale inhibitor is eluted from the core plug slightly faster than inthe experiment which used the aqueous DETAPMP solution (Flood 1).Without wishing to be bound by any theory, this could be due to thesurfactants in the emulsion promoting oil-wetting of the rock and hencereducing inhibitor adsorption, or the emulsion may not contact as muchof the rock as the test using the aqueous solution of scale inhibitor.The inhibitor concentration in the brine phase is such that the rockwill be saturated if it contacts the injected slug, and furthermore, theinhibitor solution in the emulsion is twice as concentrated as theaqueous solution of scale inhibitor, which would promote adsorption ifthe equilibrium concentration is below the saturation value. It isbelieved that dispersion during injection and diffusion during shut inoccurs less readily with the higher viscosity and reduced brine volumeof the admixture of Emulsion C and demulsifier compared to the aqueoussolution of scale inhibitor. However, in the field situation, whenproduction restarts after an emulsion treatment the inhibitor will beable to adsorb on the rock between the treatment placement depth and thewell bore, since that part of the formation will be separated from theinhibitor by the emulsions' external oil phase during injection. Thiscould reduce the high initial returns typically observed with squeezetreatments, and extend the squeeze lifetime. TABLE 1 Compositionaldetails and mixing conditions of the emulsion formulations Vol % Wt %Emulsion Inhibitor kerosene surfactant Mixing conditions A copolymer ofvinyl 52.4 0.65% sorbitan High shear mixing at sulfonate and acrylicmonooleate 15,000 rpm, 30s acid (ex Baker Petrolite; ML 3263) Bcopolymer of vinyl 52.5 0.61% Hypermer High shear mixing at sulfonateand acrylic B246 (ex ICI) 15,000 rpm, 30s acid (ex Baker Petrolite; ML3263) C DETAPMP 47.2 1.13 % Aqueous phase added neutralised to pH 2.3Hypermer B246 to kerosene phase over 30s with high shear mixing at 5,000rpm followed by high shear mixing at 20,000 rpm, 60s

[0063] TABLE 2 Physical characteristics of the emulsions MedianViscosity Stability^(b) at diameter (mPas) (° C.) Emulsion (μm)^(a) at5° C./1s⁻¹ 80 100 120 A 7.2 210 S U — B 4.9 120 S U — C 1.0-5.0 110 S U—

[0064] all formulations were stable under ambient conditions aftermixing with demulsifier—no emulsion breakdown occurred even afterseveral days TABLE 3 Sandstone core flood results Flood Number 1 2 3Inhibitor Slug DETAPMP Emulsion C Emulsion C Solution Slug Size (PV) 0.50.5 0.5 Brine K_(abs) (mD) 562 665 727 Initial K_(w) (mD) 58 70 72Initial S_(or) (%) 35.7 36.6 33.2 Initial K_(o) (mD) 411 311 451 InitialS_(wi) (%) 38.4 36.8 39.0 Post inhibitor K_(o) 420 271 427 (mD) Postinhibitor S_(wi) 36.7 34.6 39.7 (%) Final K_(w) (mD) 43 54 61 FinalS_(or) (%) 42.7 46.3 46.3 Final K_(o) (mD) 42.1 294 436 Final S_(wi) (%)36.9 29.2 37.2

1. A method of treating a subterranean formation, the method comprising:(A) injecting down a well bore into the formation an admixture of (a) anemulsion having an internal aqueous phase comprising a water-soluble oilor gas field chemical or an aqueous dispersion of a water-dispersibleoil Of gas field chemical and an external oil phase comprising a liquidhydrocarbon and an oil-soluble surfactant and (b) a demulsifiercomprising a solution of a surfactant having a cloud point temperatureof above 40° C.; or (B) separately injecting down a well bore into theformation emulsion (a) and demulsifier (b) and generating an admixtureof emulsion (a) and demulsifier (b) within the formation.
 2. A methodaccording to claim 1 wherein the admixture of emulsion and demulsifieris generated within the formation by injecting the emulsion down thewell bore prior to injection of the demulsifier.
 3. A method accordingto claim 1 wherein the admixture of emulsion and demulsifier isgenerated within the formation by injecting the demulsifier down thewell bore prior to injection of the emulsion and back producing thedemulsifier over the emulsion.
 4. A method according to claims 2 or 3wherein a spacer is injected down the well bore between the emulsion anddemulsifier.
 5. A method according to claim 1 comprising the steps of:A) preparing an admixture of the emulsion and demulsifier; and B)injecting the admixture down a well bore into the formation.
 6. A methodaccording to claim 5 wherein the time interval between preparation ofthe admixture and injection of the admixture down the wellbore is lessthan 5 hours.
 7. A method according to any one of the preceding claimswherein the water-soluble or water-dispersible oil or gas field chemicalis selected from the group consisting of (i) scale inhibitors, (ii)corrosion inhibitors, (iii) inhibitors of asphaltene deposition, (iv)hydrogen sulphide scavengers and (v) hydrate inhibitors.
 8. A methodaccording to any one of the preceding claims wherein the oil or gasfield chemical is dissolved or dispersed in the internal aqueous phaseof the emulsion in an amount in the range of from 5 to 30 percent byweight.
 9. A method according to any one of the preceding claims whereinthe oil-soluble surfactant of the emulsion has a hydrophilic/lipophilicbalance (HLB) value in the range 4 to
 6. 10. A method according to anyone of the preceding claims wherein the emulsion has droplets of theinternal aqueous phase having average diameters of from 0.1 to 10microns.
 11. A method according to any one of the preceding claimswherein the internal aqueous phase of the emulsion amounts to from 30 to60 percent of the total volume of the emulsion.
 12. A method accordingto any one of the preceding claims wherein the demulsifier comprises asolution of a surfactant having a cloud point temperature of at least60° C.
 13. A method according to any one of the preceding claims whereinthe demulsifier comprises a solution of a surfactant having a cloudpoint temperature of at least 50° C. less than the formationtemperature.
 14. A method according to any one of the preceding claimswherein the demulsifier comprises at least one surfactant selected fromthe group consisting of: (a) polyamine salts such as polyester amines,amino methylated poly acrylamide, poly di-methyl amino propylmethacrylamide, poly dimethyl amino ethyl acrylate, poly ethylene imine,poly vinyl pyrrolidone, caprolactam-based polymers and quaternisedversions thereof; (b) multifunctional polyethers such as sulfatedtriglycerides; (c) polyethers, such as copolymers of ethylene oxide andpropylene oxide and the reaction products of such copolymers withdiacids, diepoxides, diisocyanates, aldehydes, and diamines; and (d)palkylphenol-formaldehyde resins and ethylene oxide and/or propyleneoxide derivatives thereof.
 15. A method according to any one of thepreceding claims wherein the demulsifier comprises a solution of atleast one surfactant dissolved in a solvent selected from the groupconsisting of monoethylene glycol (MEG), tetraethylene glycol (TEG),butylethylene glycol (BGE), butyldiethylene glycol (BDGE), water, xyleneand toluene.
 16. A method according to any one of the preceding claimswherein the concentration of surfactant in the demulsifier is in therange of from 0.1 to 2 percent by weight.
 17. Use of an admixture of anemulsion and demulsifier as defined in any one of the preceding claimsto treat an oil or gas well.